Carbon dioxide is a useful chemical for enhanced oil recovery by means of injecting it into an oil reservoir where it tends to dissolve into the oil in place, thereby reducing its viscosity and thus making it more mobile for movement toward the producing well. Other commercial uses of CO2 are as carbonation in beverages, a mild acidification chemical and as a cooling agent in the form of a liquid or a solid (i.e. “dry ice”).
Emissions of CO2 into the atmosphere are thought to be harmful due to its “greenhouse gas” property contributing to global warming. The major source of anthropogenic CO2 is the combustion of fossil fuels. The largest sources of CO2 emissions are coal combustion for electricity generation, the use of coke for steelmaking and the use of petroleum products as a transportation and heating fuel. Other sources are natural gas fired electrical generating stations, industrial boilers for generating steam and for co-generating steam and electricity, the tail gas from fluidized catalytic cracking unit regenerators and the combustion of petroleum coke as a fuel. Gas streams emitted from such facilities may contain a significant amount of CO2, which could be recovered and used in other industrial processes.
By way of example, flue gas from coal fired thermal generating stations or steam boilers is a plentiful source of CO2 suitable for capture, often containing about 12% CO2 by volume. The flue gas usually also contains residual oxygen (2-5% volume), nitrogen and sulfur oxides and particulate matter (“fly ash”). NO is produced during the combustion process by reaction of the nitrogen content of the fuel with oxygen and also by the oxidation of the nitrogen of the combustion air at the high combustion temperature. The NO may then be partially oxidized to NO2 by the residual O2 in the flue gas. The extent of this reaction is usually quite small, so that the NO/NO2 ratio in most of the waste gas streams discussed previously herein is quite large, and particularly so in flue gas. Most coal derived flue gases also contain sulfur oxides, principally SO2, with a much lesser amount of SO3. The SO3 will react with water vapor present in the flue gas to form sulfuric acid (H2SO4) at temperatures below about 339° C. and will then condense into fine droplets (“acid mist”) as the flue gas cools. Further, other acidic contaminants, such as hydrogen chloride and hydrofluoric acid, may also be present in some flue gas streams. Solid contaminants such as FCC catalyst fines, unburned carbon or metal oxides are also often present in some flue gases.
The emission of all of these minor contaminants is generally regulated in order to preserve air quality and prevent acid rain and smog. Often, a process for the capture of CO2 also aids in controlling the regulated pollutants. Processes have been developed and are in use to capture CO2 and/or to purify gas streams to the levels regulated by government.
Many processes have been developed for the capture of CO2 from gas streams, including polymer and inorganic membrane permeation, removal by adsorbents such as molecular sieves, cryogenic separation, scrubbing with a solvent that is chemically reactive with CO2 and/or a physical solvent. The removal of CO2 from flue gas imposes requirements, which limit the choice of practicable processes to only a few. The operating conditions which have limited the current choice in selecting a commercial process include: (1) the low partial pressure of CO2 (e.g., that of 12 vol. % CO2 in flue gas at atmospheric pressure, or about 90 mm Hg CO2 pressure), (2) the presence of oxygen in the gas, which can cause oxidative degradation of the solvent, (3) the large flow rates of gas which require very low volatility of the solvent to minimize losses into the treated gas, and (4) a need for low energy consumption by the process. Additionally, any proposed process requires low capital and operating costs, be safe and environmentally friendly and must also be robust and easily operable.
One of the most successful commercial process for CO2 removal from flue gas is the use aqueous monoethanolamine (MEA) as the solvent in an absorption/stripping type of regenerative process. This process is being used commercially for CO2 capture from coal fired power plants and gas turbines. Several deficiencies inherent to the MEA absorbent have however prevented wider adoption of the technology. First, the energy consumption of the process is quite high. The MEA process may consume 10-30% of the steam generated in a boiler heated by combustion of a fossil fuel, depending on the configuration and energy integration.
Secondly, oxidation of the MEA absorbent acidifies the solvent, making it corrosive in addition to causing a loss in available alkalinity for CO2 capture. In particular, the oxidation of the MEA causes formation of ammonia and various organic acids as byproducts. The organic acid byproducts are very corrosive, requiring the use of corrosion resistant materials of construction and/or corrosion inhibitors.
Thirdly, any strong acid impurities in the flue gas will react with and deactivate the MEA preventing or limiting further absorption. Typically, the feed stream to an MEA CO2 capture process contains relatively high levels of strong acids such as sulfur dioxide (SO2), sulfuric acid mist, hydrogen chloride and NO2 which will neutralize the alkalinity of MEA. Thus either only relatively clean gas streams can be utilized or a pretreatment process is required. Accordingly, a removal step for these strong acids upstream of the CO2 absorption step or a means of removing these acids from the MEA solution, where they form so-called heat stable amine salts (HSAS), is required for typical flue gases since they contain a substantial amount of these components. These acidic contaminants, including SO2, NO2, sulfuric acid and HCl are typically captured before the CO2 capture from the gas stream by contact with an alkaline liquid in which they are readily soluble. Examples of stoichiometric or irreversible reactants which may be used upstream of a MEA adsorption/stripping process are water solutions or slurries of caustic, soda ash (sodium carbonate), lime and limestone. Regenerable or equilibrium absorbents comprising amine solutions can be practiced for SO2 removal if it is desired to recover the SO2 as a concentrated usable byproduct.
Fourthly, MEA has a relatively high vapor pressure resulting in physical equilibrium losses of MEA into the treated gas. MEA vapor pressure over a 30% aqueous solution at a scrubbing temperature of 60° C. is approximately 0.2 mm Hg while the vapor pressure of pure MEA at 120° C. regeneration temperature is 120 mm Hg. Unless measures are taken to wash the MEA out of the treated gas, the treated gas may contain about 260 ppmv of MEA, which is unacceptable from both an economic and pollution point of view. Thus the gas must be treated for recovery of the MEA by, e.g., a water wash after the contact with the MEA solution for CO2 capture.
Fifthly, the thermal and chemical degradation of MEA due to reaction between MEA and CO2 and thermal degradation of MEA can render the MEA unsuitable for continued use thus requiring the use of substantial amounts of fresh make up absorbent.
Particulate matter, if present, is also usually removed upstream of the MEA absorber, by means such as cyclones, spray scrubbers, venturi scrubbers, baghouse filters and wet or dry electrostatic precipitators. The choice of particulate removal process is made on the basis of economics and the size, quantity and nature of the dust.
Sixthly, flue gases generally also contain nitrogen oxides, NOx, mainly nitric oxide, NO, and a minor proportion of nitrogen dioxide, NO2. Since these are responsible for smog, it is desirable to remove them also. MEA scrubbing for CO2 captures some NO2 but does not remove the major NO component.
The emission of NOx can be controlled by a variety of means, differing in cost and effectiveness. Combustion modifications, such as low-NOx burners, overfire air and flue gas recirculation are inexpensive but generally are incapable of greater than about 50-60% NOx reduction. Selective noncatalytic reduction (SNCR), consisting of injecting a reactant such as ammonia or urea into hot flue gas, is somewhat more expensive but is generally not capable of NOx reduction exceeding 70%. Selective catalytic reduction (SCR) requires temperatures in the 300-400° C. range and can achieve over 90% NO reduction. However, SCR is quite expensive and can be adversely affected by other contaminants in the feed gas, which deactivate the catalyst. Adsorption processes have been proposed for NOx removal but have not found commercial acceptance due to poor cost-effectiveness and a high degree of process complexity.
Wet scrubbing processes for NO removal are known in the art. Nitric oxide is sparsely soluble in water and other solvents and it is not acidic, precluding effective scrubbing with alkaline solutions. Two principal stratagems have been used to overcome the low solubility problem. One means is oxidation of NO to NO2 or higher oxides such as N2O5, which are water soluble, by a variety of agents such as ozone, chlorine dioxide (ClO2) and potassium permanganate (KMnO4), usually followed by alkaline scrubbing. These processes can be highly effective, but the operating cost of these processes is generally high due to the stoichiometric consumption of expensive oxidizing agent fed to the process or generated in situ, as in the use of corona discharge in O2 containing gases to produce ozone, O3. Furthermore, the oxidation step and the absorption of the products into an alkali solution usually necessitates two separate pieces of equipment in the gas flow, since the oxidation and alkaline absorption are preferably practiced as separate steps.
A second means of increasing NO solubility in aqueous systems is to add a metal chelate compound which is capable of binding to NO. For instance, the use of limestone or lime slurry containing an Fe, Cu, Zn, Co, or Ni complex with ethylenediamine tetraacetic acid (EDTA) or nitrilotriacetic acid (NTA) is claimed to remove >90% SO2 and ˜70% NO (Japan Kokai, JP 53090181 780808, Akiyama, I., Okiura, K., Ota, M., Takahashi, Y. and Tahara, H.). Many publications and patents report the use of the ethylenediaminetetraacetic acid (EDTA) and its salts such as the disodium (Na2EDTA) or tetrasodium salt (Na4EDTA) as the preferred chelating agent and ferrous iron (FeII) as the preferred metal (U.S. Pat. No. 5,891,408, Buisman et al., U.S. Pat. No. 5,785,841, Tseng, and U.S. Pat. No. 5,695,727, College et al.).
The simultaneous removal of SO2 and NOx is described in a co-pending patent application, U.S. patent application Ser. No. 10/211,514; Hakka and Ouimet, the disclosure of which is incorporated herein by reference. In that process, a method of removing NO from a gas stream is disclosed. The method comprises (a) reacting NO with an absorbent to form an absorbent solution containing a nitrosyl complex at a pH from about 5 to about 7; (b) reacting the nitrosyl complex with a reduced sulfur reagent to produce recoverable reaction products containing nitrogen and/or sulfur atoms and to regenerate the absorbent whereby a regenerated absorbent solution is formed; and, (c) separating recoverable reaction products from the regenerated absorbent solution. The nitrosyl complex is preferably an iron nitrosyl complex. Preferably, the absorbent is selected from the group consisting of an iron amine polycarboxylic acid complex, an iron nitrilotriacetic acid complex, an iron hydroxyethyl ethylenediaminetriacetic acid complex and an iron diethylenetriaminepentaacetic acid complex.
Feed to SOx/NOx removal process is normally pretreated to remove particulate materials, including sulfuric acid mist, by various standard methods such as dry electrostatic precipitators, wet electrostatic precipitators, baghouses, lime injection into the gas stream for acid mist capture, water spray scrubbers and venturi scrubbers.